5.1. FIRST WATERFLOODING
Smaller fracture width (0.2 cm) resulted in higher oil recovery than others during first waterflooding process. The oil recovery factor was 21.6%, 17.9%, and 16.3% at 0.2cm, 05cm, and 0.8cm fracture width, respectively, due to fracture width effect. The presence of fractures dramatically influences the flow of fluids in a reservoir because of the large contrast in transmissibility between the fracture and the matrix. High permeable fractures carry most of the flow (Martin A. Ferno, 2012).The water-wet core samples exhibited higher oil recovery factor (29.8%) than oil-wet core samples (21.6%) during first waterflooding, which is consistent with the observation from Morrow (1990); that is the oil recovery decreased with decreasing water-wetness.
0 0.2 0.4 0.6 0.8 1 0 1 2 3 4 5 Efflu e nt Conc e ntra tio n, % NaCl PV
15 psi 100 psi 200 psi WF1
WF2 PPG
5.2. PPG PLACEMENT
The results showed that oil recovery improvement during PPG injection because the swelling capacity (swelling ratio) increased as the brine concentration decreased. A large amount of water was forced into matrix when the PPG swelled in low water salinity (high swelling ratio) due to high swelling ratio. When the amount of water that was forced into matrix increased, the sweep efficiency increased and, in turn, oil recovery improved. Because these large amount of water that was forced into matrix was low-salinity water, the wettability of matrix was changed to be more water wetness and resulted in improved displacement efficiency. Therefore, Combining PPGs with low-salinity water might be improved both sweep and displacement efficiency. The improved oil recovery where a fracture width of 0.2 cm was higher than that from other fracture widths during microgel injection because the smaller fracture width resulted in higher resistance to water flow. For oil-wet core samples, Figure 7 showed the low-salinity water had a significant effect on oil recovery factor during PPG injection. The oil recovery was improved by 11.8% when low- salinity water used to swell the PPG while it was improved by 3.8% when normal brine used to swell the PPG. So the differences in the improvement of oil recovery was 8% when low-salinity and normal brine were used.
For water-wet core samples, Figure 18 showed the low-salinity water had no significant effect on oil recovery factor during PPG injection. The oil recovery was improved by 13% when low-salinity water used to swell the PPG while it was improved by 11% when normal brine used to swell the PPG. So the differences in the improvement of oil recovery was 3% when low-salinity and normal brine were used. This difference was resulted only from
improving in sweep efficiency and there was no effect for low-salinity water on wettability alteration because the core sample was water-wet.
Six imbibition tests were performed using two water wet cores and four oil wet cores, as shown in Figure24. The oil recovery depended on the rock wettability and water salinity. Water wet cores had better oil recovery than oil wet cores. In the first two days, water wet cores had oil recovery of 1.3%, while the oil wet cores had the same oil recovery but after 3 days. Throughout 40 days, oil recovery determined from the water-wet samples was significantly larger than the oil recovery determined from oil- wet samples. Water-wet core imbibed in 1% NaCl had four times (~20%) oil recovery larger than oil recovery determined from oil-wet cores (5%) imbibed in same NaCl concentration. Water salinity also impacted the oil recovery; oil recovery increased as the water salinity decreased. Oil recovery was 5%, 7.5%, 10%, and 12% after cores being imbibed into NaCl concentration of 1%, 0.1, 0.01, and 0.001%, respectively. However, no significant effects of low salinity water on the oil recovery factor was observed for the water-wet cores. D.C. Strand (2001) showed that only 3.4 % of OOIP was produced after 1 day. He reported that the time delay before the imbibition initiated was expected to be due to high adsorption of surface-active material at the boundary of the core. Increased water-wetness inside the core implied faster imbibition at a later stage in the imbibition process. Also, the oil recovery during viscous flooding was higher than spontaneous imbibition because during the viscous flood, the external pressure was to force the water to imbibe inside the matrix (forced imbibition) which leads to release more oil drops comparison with spontaneous imbibition.
From the above results, we can conclude that combined PPG with low-salinity water might be improved both sweep and displacement efficiency in oil-wet core samples
while they improved only sweep efficiency in oil-wet core samples. PPG placing pressure had a significant effect on the oil recovery factor. When the placement pressure increased, the fracture conductivity decreased, and higher volume of water was forced into matrix and, in turn, the oil recovery factor increased.
Figure 24. Spontaneous imbibition test results.
5.3. SECOND WATERFLOODING
The oil recovery increased more when microgel swelled in low water salinity filled the fracture than others during the second waterflooding due to gel strength effect. At high swelling ratio, the PPGs were more deformable because the gel strength decreased as water salinity decreased and efficiently reduced the permeability of the fracture. This resulted in increased water residual resistance and, in turn, more brine solution was diverted into the matrix and more oil was recovered. The higher oil recovery was improved from water-wet core sample than that from oil-wet core sample during the second waterflooding because of the wettability effect. Also, the oil recovery during second waterflooding improved as
0 5 10 15 20 25 0 5 10 15 20 25 30 35 40 45 Oi l R e co ve ry Fac to r, % Time ,Day
1.0 wt.% NaCl (Oil-Wet) 0.1 wt. % NaCl (Oil-Wet) 0.01 wt. % NaCl (Oil-Wet) 0.001 wt.% NaCl (Oil-Wet) 1.0 wt.% NaCl (Water-Wet) 0.01 wt.% NaCl (Water-Wet)
much as PPG placed pressure. The water residual resistance factor also increased considerably as the PPG placing pressure increased. Therefore, the fracture conductivity decreased and more water were diverted to matrix resulted in improved oil recovery. When gel particles placed in the fracture, both low salinity gel and high salinity gel, the gel pressurized until the injection pressure reached 15 psi (in some experiments 100 and 200 psi). Therefore the gel particles will loss most of the water and those sizes will be decreased a lot before stating second water flooding. Thus, the effect of 1.0% NaCl on PPG shrink is negligible.
6. CONCLUSIONS
A series of core flooding tests using fractured limestone core models identified whether the couple process of PPG treatment and low salinity water flooding can improve oil recovery during mixing injection method. Four key parameters were evaluated, including the swelling ratio, fracture width, wettability, and PPG-placing pressure. The results yielded the following conclusions:
Combining PPGs with low water salinity as a mixed mode is a viable technique for improving oil recovery in fractured carbonate reservoirs.
The increase in PPG size (swelling ratio) during PPG placement allowed the PPGs to more efficiently reduce fracture permeability. PPGs can increase oil recovery from narrow fractures at much higher rates than from wide fractures.
Core flooding results indicated that the combining method (PPG with low water salinity in one process) improved oil recovery significantly from both oil-wet and water-wet cores.
PPG placing pressure affects the oil recovery factor and water residual resistance factor. When the placing pressure increases, the oil recovery factor and the water residual resistance factor increases. The combined method has more effect on oil recovery at a higher placing pressure. The highest PPG placed pressure was a result of a higher rate of lowest salinity water flowing into the matrix.
ACKNOWLEDGEMENTS
The authors would like to express their grateful acknowledge to the financial support from DOE under the contract of DE-FE0024558.Also, the authors also would like to express their appreciation to the Higher Committee for Education Development in Iraq (HCED) and the Missan Oil Company for their support.
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III. COMBINED IONICALLY MODIFIED SEAWATER AND MICROGELS TO